Extraction of hydrocarbons from subterranean formations is an important global industry. Fuels derived from these hydrocarbons form the core energy supply for most of the industrialized world. The petroleum industry is faced with two significant challenges. On one hand, the conventional light oil has mostly been depleted via the primary production and waterflood and enhanced recovery processes must be enacted to increase the production. The enhancement typically relies on injection of external materials in one well, which then sweeps the remaining in-situ hydrocarbon liquid towards the production well.
On the other hand, unconventional oil reservoirs are difficult to produce via primary production means and must rely on stimulation. In North America and many other parts of the world, hydrocarbons are found in heavy and viscous forms such as bitumen and heavy oils, which are extremely difficult to extract. The bitumen-saturated oilsands reservoirs of Canada, Venezuela, California, China and other parts of the world are just some examples of such subterranean formations. In these formations, it is not possible to simply drill wells and pump out the oil. Instead, the reservoirs are heated or otherwise stimulated to reduce viscosity and promote extraction. Steam flooding, Cyclic Steam Stimulation (CSS) and Steam Assisted Gravity Drainage (SAGD) are some of the examples.
In either enhanced recovery of the conventional reservoirs or stimulation of the unconventional oil reservoirs, their production depends on two major functions acting simultaneously: one is stimulation and the other is sufficient drive energy. As an example of stimulation, viscosity of the in-situ heavy oil or bitumen is reduced through injection of steam, solvent or whatever other materials. In another example, interfacial tension between the in-situ hydrocarbon liquid and the displacing fluid is reduced by injection of chemicals so that it becomes more readily mobile. Equally important is the contact area for the injected materials with the reservoir. A contact area as large as possible and attained as early as possible is desired.
The other major function in producing the conventional reservoirs via enhanced recovery processes or producing the unconventional reservoirs via stimulation is to provide sufficient drive energy for the stimulated hydrocarbon liquid to be produced. In steam flooding, the driving energy is the pressure difference between the injection and production wells. In CSS, the drive energy is the pressure difference between inside the reservoir and the production well. In SAGD, the drive energy is gravity.
The above-described two functions should work together simultaneously. For example, in steam flooding, the pressure difference provides significant drive energy for the production. However, injected steam can easily and undesirably travel over the in-situ hydrocarbon liquid thereby bypassing the desired product to be flooded. When this breakthrough occurs, the drive energy from the pressure difference becomes significantly reduced. In addition, it has been realized, for example in Butler, U.S. Pat. No. 4,344,485, that fluid mobility is restricted at the flooding front where the mobilized hydrocarbon, injected materials and in-situ hydrocarbon are mixed together.
Recognizing the problem of restricted fluid mobility at the flooding front, Shell Canada Ltd. has experimented using the CSS process to first produce from behind the flooding front until fluid mobility restriction is eventually overcome, then steam flooding is used. Their process is described not to rely on gravity or vertical flow (Section 4.1 in “Application for Approval of the Carmen Creek Project, Volume 1: Project Description” made to Energy Resource Conservation Board (ERCB) of Alberta, Canada in November 2009). The whole reservoir thickness is open to the steam injection.
In SAGD, the drive energy comes from the gravity. It uses steam or other viscosity-reducing agent to contact the reservoir. The viscosity-reduced bitumen or heavy oil drains away from the contact front due to the density difference between the various phases, making the contact front substantially full of fresh injected steam or other agents.
Despite its commercial success, the SAGD process is still subject to the following drawbacks:                (1) Its contact with the reservoir is relatively small. This is especially true during the early stage of the operation. In the conventional circulation start-up phase of a SAGD operation made up of a horizontal well pair, the reservoir contact is near-cylindrical shaped and more or less co-axial with the wells. During the ramping up phase, the steam chamber extends nearly vertically to the reservoir top, increasing the reservoir contact to a near-rectangular shape extending along the horizontal well length. During the blow-down phase, the reservoir contact spreads out laterally but does not spread across the whole reservoir width. The less the contact area, the less stimulation, and the less production.        (2) Gravity as the driving force in reservoir production is less energetic that pressure differential. As the SAGD steam chamber reaches the reservoir top, it spreads laterally and its slope gradually decreases, thus reducing effectiveness of the gravity drainage.        (3) In SAGD, the steam chamber reaches the reservoir top very early. Afterwards, it spreads out laterally, which causes more and more thermal energy to be lost to the overburden rock. Moreover, long periods of heat contacting the overburden rock can also induce rock deformation, causing the caprock integrity concerns. SAGD is not applicable or less economic in reservoirs with complex geological features at their top, such as top gas, top water, compromised or non-existent competent caprock. A SAGD operation may not be economic in a thin reservoir due to the energy loss to the overburden.        (4) In a SAGD pad, a pocket of unrecovered bitumen forms in the space between two adjacent well pairs. An additional well can be drilled to access the bitumen for increasing the total recovery of oil but drilling cost is high.        
In the injection cycles of a CSS process, steam is injected into the formation at pressures high enough to dilate the pore spaces. At the end of the injection cycles the pressure and temperature are the highest in the vicinity of the well and so is the steam saturation. At the beginning of the production cycles, steam with the highest energy values has to be recovered first before the oil from the remote portions of the reservoir can be produced as the reservoir pressure becomes low. Therefore, the major drawbacks of the CSS process are: (1) the energy efficiency is low due to the fact that heating value produced at the beginning does not contribute much to the oil production, (2) the displacement process is not efficient because the swept zone near the production well becomes increasingly larger with the cycles and the back and forth flow of the steam in this zone, and (3) in the late cycles the oil produced from remote portions of the reservoir has to flow through a long distance of the swept zone to be produced.
There is therefore a need to provide stimulation or enhanced recovery processes that optimize simultaneously on stimulation and drive energy.